1. Field of the Invention
The present invention relates to methods and apparatus for determining in situ the properties of oil. The present invention more particularly relates to methods and apparatus for determining oil characteristics such as mass or electron density and/or the presence of unwanted elements in the oil such as sulfur. The invention has particular application to both oilfield exploration and production, although it is not limited thereto.
2. State of the Art
Those skilled in the art will appreciate that the ability to conduct an analysis of formation fluids downhole (in situ) is extremely desirable for several reasons. First, the in situ formation fluid analysis can determine the economical value of the crude oil in the formation. Second, the analysis can permit monitoring of filtrate contamination in wells drilled with an oil based mud. Third, a proper downhole analysis permits the typing of oil in multiple producing zones. With that in mind, the assignee of this application has provided a commercially successful borehole tool, the MDT (a trademark of Schlumberger) which extracts and analyzes a flow stream of fluid from a formation in a manner substantially as set forth in co-owned U.S. Pat. Nos. 3,859,851 and 3,780,575 to Urbanosky which are hereby incorporated by reference herein in their entireties. The OFA (a trademark of Schlumberger), which is a module of the MDT, determines the identity of the fluids in the MDT flow stream and quantifies the oil and water content based on the previously incorporated related patents. In particular, U.S. Pat. No. 4,994,671 to Safinya et al., which is hereby incorporated by reference herein in its entirety provides a borehole apparatus which includes a testing chamber, means for directing a sample of fluid into the chamber, a light source preferably emitting near infrared rays and visible light, a spectral detector, a data base means, and a processing means. Fluids drawn from the formation into the testing chamber are analyzed by directing the light at the fluids, detecting the spectrum of the transmitted and/or backscattered light, and processing the information accordingly (and preferably based on the information in the data base relating to different spectra), in order to quantify the amount of water and oil in the fluid. As set forth U.S. Pat. No. 5,266,800 to Mullins which is hereby incorporated by reference herein in its entirety, by monitoring optical absorption spectrum of the fluid samples obtained over time, a determination can be made as to when a formation oil is being obtained as opposed to a mud filtrate. Thus, the formation oil can be properly analyzed and quantified by type. Further, as set forth in U.S. Pat. No. 5,331,156 to Hines et al., which is hereby incorporated by reference herein in its entirety, by making optical measurements of the fluid stream at certain predetermined energies, oil and water fractions of a two-phase fluid stream may be quantified.
As previously suggested, the measurement of fluid density is of great importance to the oil industry. Dead crude oil (i.e., oil at the formation surface and at ambient pressure) consists primarily of carbon and hydrogen with some contaminants or unwanted elements such as sulfur which constitute by weight a few percent of the oil. Generally, the economic value of the crude oil increases with its hydrogen content, as valuable fluids such as gasoline which are constituted of saturated hydrocarbons have an H to C ratio of approximately 2, whereas the least valuable component of crude oil, asphaltene, has an H to C ratio of approximately 1.1. Asphaltenes are primarily large aromatic molecules of considerable densities. Thus, in a crude oil, a high density is generally indicative of a high asphaltene content.
The presence of a large amount of asphaltenes in oil is undesirable from both a production viewpoint and from a processing viewpoint. In production, asphaltenes are known to plug oil wells. Asphaltenes are components of crude oil that are often found in colloidal suspension in the formation fluid. If for any reason the colloidal suspension becomes unstable, the colloidal particles will precipitate, stick together and, especially in circumstances where the asphaltenes include resins, plug the well. Asphaltene precipitation during production causes severe problems. Plugging of tubing and surface facilities disrupts production and adds cost. Plugging of the formation itself is very difficult and expensive to reverse, especially for a deep water well. In processing oil that has been produced, asphaltenes are likewise undesirable as catalytic cracking will yield some low-grade coke that is not a valuable commodity.
Currently, the stock tank density of crude oil is the primary determinant of the economic value of the crude oil. It is therefore desirable to oil producers to be able to determine what the stock tank density of oil located in a formation will be after it is produced. However, downhole determinations of oil density are often subject to inaccuracies. For example, it is common for crude oil to have methane gas dissolved in the oil. When produced, the methane gas separates out of the oil and must be disposed of properly. Thus, when methane gas is present, the methane gas increases the hydrogen content of the oil downhole (and decreases the density), which provides an inaccurate reflection of the stock tank density uphole.
While a downhole densitometer has been suggested by Pettetier, Michael T., et al. in patent publication WO/01/51898A1, the provided apparatus is subject to significant error. In particular, the suggested device includes two resonant cavities; one filled with the sample fluid, and the other filled with a known fluid. The sample fluid density is determined from the difference in resonant frequencies between the two cavities and the density of the known fluid. However, since the reference frequency of the known fluid is subject to change with temperature and pressure, significant errors are likely.
Terminology
For purposes of understanding the invention, the following parameters are used and are to be understood as follows:
Avogadro's numberN0 = 6.023 × 1023 (dimensionless)Mass densityρ (g/cm3)Electron densityne = # of electrons/cm3Atomic numberZ = # of electrons per atom(dimensionless)Atomic massA = the total mass of N0 atoms withatomic number Z (g)Number densityn = number of nuclei per unit volumecm−3cross sectionσ (cm2) mass attenuationcoefficient      μ    m    =                    n        ×        σ            ρ        =                            N          0                A            ⁢      σ      ⁢                          ⁢              (                              cm            2                    /          g                )            